1

Kansas City/Dallas Investor MeetingsMARCH 2 & 3, 2010

2

This presentation contains statements concerning NU’s expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In some cases, a listener or reader can identify these forward-looking statements through the use of words or phrases such as “estimate”, “expect”, “anticipate”, “intend”, “plan”, “project”, “believe”, “forecast”, “should”, “could”, and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to, actions or inaction of local, state and federal regulatory and taxing bodies; changes in business and economic conditions, including their impact on interest rates, bad debt expense and demand for our products and services; changes in weather patterns; changes in laws, regulations or regulatory policy; changes in levels and timing of capital expenditures; disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly; developments in legal or public policy doctrines; technological developments; changes in accounting standards and financial reporting regulations; fluctuations in the value of our remaining competitive electricity positions; actions of rating agencies; and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the Securities and Exchange Commission (SEC). Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update the information contained in any forward-looking statements to reflect developments or circumstances occurring after the statement is made or to reflect the occurrence of unanticipated events.

This presentation includes non-GAAP financial measures referencing our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation and our 2006 EPS excluding two significant, discrete impacts, which are the results of our competitive generation business that included a significant gain from the sale of such business and a reduction in income tax expense pursuant to a Private Letter Ruling issued by the Internal Revenue Service. Due to the nature and significance of these items, management believes that the relative non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this presentation in analyzing historical and future performance. This presentation also references actual and projected EPS by business, a non-GAAP presentation, which management believes is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses. These non-GAAP financial measures should not be considered as alternatives to our consolidated net income attributable to controlling interests, and EPS determined in accordance with GAAP as an indicator of operating performance. Please refer to the reconciliations of these non-GAAP financial measures to our consolidated net income attributable to controlling interests, EPS included as an Appendix to this presentation.

Please refer to our reports to the SEC for further details concerning the matters described in this presentation.

Safe Harbor Provisions

3

$13.1

$138.3$150.8

$290.6

($11.6)

$330.0

$15.8($9.3)

$164.3$159.2

($25)

$25

$75

$125

$175

$225

$275

$325

$375

2008

2009

2009 Results

Distribution and Generation

Transmission Parent/Other Competitive Total

*Excludes $29.8 million after-tax charge from March 2008 litigation settlement

5.6% 18.8%

*

13.6%

Ear

nin

gs

Fo

r C

om

mo

n In

Mill

ion

s

*

4

2009 Distribution and Generation Results

$27.1

$41.4

$70.0

$12.3

$21.0

$16.7

$47.5

$74.0

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

2008

2009

CL&P PSNH WMECO Yankee Gas

5.7%

14.7%

Ear

nin

gs

Fo

r C

om

mo

n In

Mill

ion

s

35.8%

22.5%

5

Increased Transmission Investment Has Diversified and Significantly Increased Regulated Earnings

$41.1

$122.3$164.3

2005 2009

Regulated Net Income(In millions)

Distribution/Generation

Transmission

Net Income: $163.4Regulated EPS: $1.24

Net Income: $323.5Regulated EPS: $1.87

74.8%

25.2%

50.8%

49.2%

$159.2

6

2008 – 2009 Results, 2010 EPS Guidance

2008 Actual* 2009 Actual 2010 Guidance

Distribution/Generation $0.96 $0.92 $0.95 - $1.05

Transmission $0.89 $0.95 $0.90 - $0.95

Competitive $0.08 $0.09 $0.00 - $0.05

NU Parent/Other excluding litigation charge in 2008

($0.07) ($0.05) ($0.05)

NU Consolidated excluding litigation charge in 2008

$1.86 $1.91 $1.80 - $2.00

Litigation charge ($0.19) N/A N/A

NU Consolidated $1.67 $1.91 $1.80 - $2.00

*See appendix for GAAP/non-GAAP reconciliation

7

Key Earnings Drivers for 2010 - 2011

2010 2011

Positive Drivers

• CL&P, PSNH rate cases (2nd half only)

• PSNH Clean Air Project construction (AFUDC)

• Higher average transmission rate base

• CL&P, PSNH rate cases • WMECO rate case, solar investment• Possible Yankee Gas rate case • PSNH Clean Air Project construction

(AFUDC)• Greater Springfield Reliability Project

construction (cash return on CWIP)• Higher average transmission rate base

Pressures

• Pension costs• Uncollectible costs• Sales • Operating expenses• Expenses associated with

investments in aging distribution infrastructure

• Sales • Operating expenses• Expenses associated with investments

in aging distribution infrastructure• Roll off of profitable NUEI contracts

8

Balance Sheet Strengthened Considerably in 2009

12/31/08 12/31/09

$4,776 $4,660

$116 $116

$3,020

$3,578

Total debt Common equity Preferred

(In millions)

38.2% 60.4%

1.4%

42.8% 55.8%

1.4%

Total: $7,912 Total: $8,354

9

History of Strong Dividend Growth Since 2001

Dividend policy ($)

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$1.75

$2.00

$2.25

2006 2007 2008 2009 2010E

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

62.5%

48.7%

44.3%

49.7%

$1.80–$2.00

$1.86²

$1.16¹

$1.59

$0.825$0.775

$0.725

$0.95

Payout ratiosEPS Dividends paid/declared per share

1 Excludes net income of competitive businesses, one-time CL&P tax reduction2 Excludes litigation settlement charge3 Based on first quarter rate of $0.25625

$1.91

$1.0253

10

Southwest Connecticut Reliability: Projects Complete

1

Connecticut Borders (MA, RI):NEEWS Projects Under Way2

Renewables & Clean Energy (ME/NH/VT):Projects in Development/High Wind potential areas

4

Renewable Collector Lines

Hydro-Quebec-HVDC

3 HVDC Line between Quebec and New Hampshire

Transmission as a Key Strategic Enabler to Solving New England’s Energy Challenges

´

´

11

NEEWS Advances Into the Siting Phase

SPRINGFIELD

HARTFORD

345-kV SubstationGeneration Station345-kV ROW

115-kV ROW

Central ConnecticutReliability Project

InterstateReliability Project

Greater SpringfieldReliability Project

GSRP Status

• ISO confirmed need date in October 2009

• CT hearings completed; MA hearings completed

• Decisions and orders expected in spring/summer 2010

• Construction start in late 2010

• In-service 2013

IRP and CCRP Status

• Updated needs assessment expected by 3Q 2010

12

Greater Springfield Interstate*

CentralConnecticut*

File Municipal Consultation Filing (MCF) Late 2010

Conduct MCF outreach Late 2010

Hold open houses Early 2011

File siting application Late 20106-12 mo. Behind

Interstate

Complete Evidentiary hearingsLate 2011/ Early 2012

6-12 mo. Behind Interstate

Receive Decision and OrderCT – 3/2010

MA – Q3 2010Mid 2012

6-12 mo. Behind Interstate

Begin Construction Late 2010 2012**6-12 mo. Behind

Interstate

Expected In-Service 2013 20146-12 mo. Behind

Interstate

Estimated cost ($Millions)

Does not include $211M in ancillary projects$714 $250 $315

NEEWS Projects - $1.49 Billion Capital Investment (2009-2014)

NEEWS Projects Milestones (as of 2/23/10)

* Depends upon the timing of a favorable outcome to ISO’s reassessment of need and need dates, which is expected in the 3d quarter of 2010.

**Depends upon timing of favorable outcome of siting in three states (CT, MA and RI)

Represents schedule updatessince November 2009

13

New HVDC Line To Connect Hydro-Quebec Generation To New England Market

´

• Joint venture between NU (75%) and NSTAR (25%)

• 1,200 MW transfer capability

• Northern terminus at Des Cantons (Québec), southern terminus in central or southern New Hampshire

• Québec terminal will convert the power from AC to DC (rectifier)

• US terminal will convert the power from DC to AC (inverter)

• Capital cost estimate for US segment: $900 million ($675 million for NU share)

• Work proceeding on Transmission Service Agreement and Purchased Power Agreement

HVDC Line

Des Cantons

HVDC Converter Station

14

Resources Required to Fill Shortfall in 2020

Wind (on-shore and off-shore)

Other Class I Technologies

~ 3,300 MW

~ 500 MW

Developing a Regional Renewable Solution for New England

New Line

Wind Zone

Electricity Demand

Estimated Class I Renewable Resource Requirements for New England (GWh) by 2020 = 22,800 GWh

6,600 GWh = Existing Available Renewables

3,500 GWh = Currently Planned or Under Development

12,700 GWh = Unplanned Renewables/Balance Shortfall

Class I Technologies include:

> Biomass/Biofuels > Fuel Cells (CT)

> Landfill Gas > Small Hydro

> Solar PV > On and Offshore Wind

Concept• Renewable Access

Transmission Line• 2,000 MW• $1.5 billion to $2

billion

New England Renewable Projections for 2020

15

2010-2014 Transmission Capital Expenditures

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Base Reliability Major Southwest CT NEEWS HQ HVDC

Historic Forecast

In M

illio

ns

Up To $2.9 Billion $2.8 Billion

SWCT projects total $1.6 billion

$900 million of other projects(Details follow)

Successful completion of

SWCT projects

US portion now estimated at

$900 million with $675 million NU ownership share

HVDC Line from Canada

NEEWS projects estimated at

$1.35 billion during 2010-2014 forecast

period

NEEWS projects ramping up

16

Capital Projects Reflected in Projected2010-2014 Transmission Year-End Rate Base

$2,022 $2,134 $2,318 $2,545 $2,563

$250 $315 $335 $433$530

$608

$130$183 $240

$429

$665

$851

$2,099 $2,105

$584

$889

$675

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

2008Actual

2009Actual

2010 2011 2012 2013 2014

CL&P PSNH WMECO Transmission from Canada

Transmission Rate Base

CAGR of 12%

In M

illio

ns

$2,402$2,597

$2,996

$3,513

$4,042

$4,673

* Reflects FERC approval of 100% CWIP for NEEWS projects

$2,680

**NU share of this project is depicted as traditional rate base without CWIP during construction

*** *

17

Regulated Distribution & Generation

18

Attractive Regulated Business Profile

Regulated companies

The Connecticut

Light and Power

Company

Yankee Gas Services Company

Public Service Company of

New Hampshire

Western Massachusetts

Electric Company

• Regulated natural gas delivery company with significant growth potential

• Largest natural gas distribution system in Connecticut as measured by number of customers (~205,000), and size of service territory (2,088 square miles)

• Regulated integrated electric utility

• 496,000 retail customers in 211 cities and towns in New Hampshire

• ~1,200MW of regulated generation assets

• Regulated T&D company

• 1.21 million retail customers in 149 cities and towns in Connecticut

• Regulated T&D company

• 205,000 retail customers in 59 cities and towns in western Massachusetts

Service territories

VTNH

MA

CT RI

Electric territory

The Connecticut Light andPower Company

Public Service Companyof New Hampshire

Western MassachusettsElectric Company

Gas territory

Yankee GasServices Company

Total customers: 2.1 million

Total assets: $14.1 billion

Electric Gas1 As of June 30, 2009

19

$283 $311 $313 306 305 317

$99$113 $111 115 121 134$38$34 $39 36 35

145

187117

82 68 26

$20

$147

36

$0

$100

$200

$300

$400

$500

$600

$700

2009Actual

2010 2011 2012 2013 2014

WMECO - Solar ($41m total)

PSNH - Generation ($480m total)

WMECO - Distribution ($180m total)

PSNH - Distribution ($594m total)

CL&P - Distribution ($1,552m total)

In

mill

ions

Electric Distribution and Generation Capital Expenditures – By Company

2010-2014 Projected Distribution & Generation Capital Spending$2.8 Billion

$565

$513$529$546

$594

$665

20

Projected 2010 – 2014 Distribution and Generation Year-End Rate Base

$1,975 $2,119 $2,333 $2,497 $2,629 $2,778 $2,911

$667$772

$849$941

$1,030$1,090

$1,156

$374$412

$413$434

$447$456

$685$691

$764$843

$892$932

$974

$370$407

$404$443

$879$902

$882

$461

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

2008Actual

2009Actual

2010 2011 2012 2013 2014

CL&P Distribution PSNH Distribution

WMECO Distribution Yankee GasPSNH and WMECO Generation

Projected Distribution & Generation Rate Base

CAGR of 8%

In M

illio

ns

$4,071

$4,763$5,158

$5,877$6,158

$6,384

$4,401

21

2010 Rate Cases

PSNH CL&P WMECO

Filing: Application filed 6/30/09 Application filed 1/08/10 Estimated 7/1/10

Key Topics:

• Rate lag• Ice storm cost recovery• Low earned ROE• Little sales growth• Rate base adds

• Aging infrastructure

• Sales declines

• Uncollectible expense

• Headroom from RRB final amortization in December 2010

• Decoupling

• Pension tracker

• Decoupling

• First full rate case in nearly 20 years

• Sales declines

• Rate base adds

Anticipated Completion Date:

7/1/10 7/1/10 1/1/11

Key Interim Dates

4/9/10: Target for settlement filing

4/20/10 – 4/22/10: Hearing

3/15/10 – 4/19/10: Hearings

5/21/10: Draft decision

6/4/10: Final decision

N/A

2009 Regulatory ROEs

7.2%

Distribution and Generation

3.6%

Distribution only

7.3% 8.4%

22

Generation Strategy

WMECO Solar InitiativeWMECO Solar InitiativeThe Clean Air ProjectThe Clean Air Project

Installation of 6 MW solar projected by 2012

First site (Pittsfield) announced in February

Estimated cost: $41 million

Constructive regulatory model – fully tracking, segmented rate base

Potential for up to 50 MW

Scrubber must be installed by 7/1/13 Will remove 90+% of sulfur, 80% of

mercury emissions Estimated cost: $457 million

Nearly $147 million capitalized at 12/31/09

Broad stakeholder support On or ahead of schedule: 40%

complete as of 2/28/10 Resolved major uncertainties

23

Yankee Gas Capital Expenditures

$23 $23 $22

$17 $22 $22 $25 $28 $30

$26$31

$31$31$32$34

$17

$17$23

$31$36

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2009Actual

2010 2011 2012 2013 2014

Aging Infrastructure Basic BusinessPeak Load / New Business WWL

2010-2014 Projected Yankee Gas Capital Spending$461 Million

Investing $461 million, leveraging natural gas as “the fuel of choice”

Distribution system expansion: $67 million, 16-mile Waterbury-to-Wallingford Line (WWL)

Sales growth opportunities to supply renewable generation (fuel cells, DG)

Yankee Gas StrategyYankee Gas Strategy

$60

$83$82$80

$104$112

In

mill

ion

s

24

Additional Initiatives Meeting Public Policy Direction

CL&P concluded a 3,000 customer AMI/rate pilot on 8/31/09 to test the technology and customer interest in dynamic pricing rates

• Good customer response

• Gained insight on customer behavior in response to dynamic pricing rates and enabling technology

• Filed results with DPUC on December 1, 2009

• Future recommendations by March 31, 2010

WMECO Smart Grid pilot plan filed with DPU on October 16, 2009

• 1,750 customer pilot - $7 million projected cost

• DPU decision expected in first half of 2010

Electric vehicle infrastructure

25

Appendix

26

$163 $136$203

$281 $286

$155

$61$55

$118

$107 $74

$22

$68$66

$256

$328

$156

$49

$90

$236

$282

$6

$16

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

2009 Actual 2010 2011 2012 2013 2014

CL&P PSNH WMECO Transmission from Canada

Projected Transmission Capital Expenditures

$292

$806

$752

$465

$626

$273

In M

illio

ns

27

Other Transmission Capital Projects in RSP, Not in RSP or Not Required to be in RSP

$0

$50

$100

$150

$200

$250

$300

$350

2009 2010 2011 2012 2013 2014

Not Required to be in RSP In RSP Not Yet in RSP

2010-2014 Transmission Capital ProgramOther Projects – In Millions

CL&P WMECO PSNH

Total $897 Million

150

259298

156

34

211

Projects not yet in Regional System Plan (RSP)

Breakdown of Other Projects:

• 45% ($401M) - in RSP

• 24% ($216M) - not required to be in RSP

• 31% ($280M) - not yet in RSP

Stamford Area Reliability $100.0 Berkshire Area Solution $170.0 Manchester Area Solution $52.3Manchester - East Hartford Line $53.4 115 KV Relay Replacements $14.4 Scobie - Tewksbury Line $52.0Southwest CT Upgrades $30.0 115 KV Reliability Project $4.0 Nashua Area Solution $51.1115 KV Relay Replacements $28.3 CCVT Replacements $3.2 Deerfield 2nd Auto Transformer $42.8South Meadow BPS $13.1 13 Additional Reliability Projects $11.6 Maine Power Reliablity $30.8CCVT Replacements $11.3 Deerfield - Webster - Coolidge $30.0Spare Bethel -Norwalk Shunt Reactor $9.8 Northern Loop $23.0Transmission Operations Center $7.7 Thornton Ferry Substation $27.7Vehicle Purchases $7.4 OPGW Communications Project $16.0New Sherwood Substation $7.2 New Pease Substation $6.048 Additional Reliability Projects $50.7 29 Additional Reliability Projects $43.1

$318.9 $203.2 $374.8

Note: Upon commencement of the ISO-NE approval process, the HVDC project will be included in the RSP

28

2005-2009 NU Consolidating EPS GAAP / Non-GAAP Reconciliation

2005 Actual

2006 Actual

2007

Actual

2008

Actual

2009

Actual

Distribution/Generation $0.93 $0.80 $0.94 $0.96 $0.92

Transmission 0.31 0.39 0.53 0.89 0.95

Total Regulated 1.24 1.19 1.47 1.85 1.87

NU Parent/Other (0.14) (0.03) 0.04 (0.07) (0.05)

Total Regulated and Parent $1.10 $1.16 $1.51 $1.78 $1.82

Competitive (3.03) (0.63) 0.08 0.08 0.09

NU Consolidated Operating Results (Non-GAAP) ($1.93) $0.53 $1.59 $1.86 $1.91

CL&P Income Tax Reduction N/A 0.48 N/A N/A N/A

Gain on Sale of Competitive Generation N/A 2.04 N/A N/A N/A

Litigation Charge N/A N/A N/A (0.19) N/A

NU Consolidated GAAP ($1.93) $3.05 $1.59 $1.67 $1.91

29

Beyond NEEWS, HQ Project, Significant Transmission

Investment Will Be Needed to Bring Renewables to Market

Connecticut

27% by 2020

Vermont

Goal: 20% by 2017

Minimum: 2005-2012. Load growth to be met with renewables and capped at 10%.

Maine

40% by 2017 (currently 30%)

New Hampshire

23.8% by 2025

RI

16% by 2020

Massachusetts

Class I Class II 4% in 2009; 1% annual 3.6% kwH sales startingincrements thereafter in 2009 & 3.5% kwH

sales from wasteenergy starting in 2009

Current New England Renewable Portfolio Requirements

30

Understanding Terms Related to the HVDC Project

• Joint Development Agreement (JDA)• Defines the terms on which we will jointly manage the development of the HVDC line with HQ-TransEnergie

• Design, engineering, siting, permitting, obtaining or preparing written cost estimates• Creates a project board with general oversight responsibility for the project• Describes the roles and responsibilities of the project board and each company’s project managers• Defines project communication protocols• Will be in place through siting approval (a separate joint construction agreement will likely be needed)• Commercial agreement not subject to regulatory review

• Transmission Service Agreement (TSA)• Sets forth the terms and conditions under which HQ will acquire and pay for the transmission use rights over the New Hampshire

segment of the HVDC line• Describes what transmission rights HQ gets (firm rights to flow power, interruption or curtailment details)• Defines process for HQ to offer the transmission rights to others at times when they might not be using the line• Defines payment terms for the line• Defines the components of the cost for the line (revenue requirements: depreciation, ROE, debt service, O&M, property taxes)• Describes needed arrangements with ISO-NE such as scheduling flows over the line, etc.)• Subject to FERC review and approval

• Power Purchase Agreement (PPA)• Defines the product HQ will sell• Defines the pricing structure for the energy• Defines the pricing structure for capacity• Defines pricing for externalities• Sets forth payment terms • Negotiations under way with expected completion in spring 2010, with state regulatory filings sequenced to coincide with ISO,

technical and state specific timetables